This section is intended to introduce various aspects of the art. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Modern society is greatly dependent on the use of hydrocarbons for fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface rock formations that can be termed “reservoirs.” Removing hydrocarbons from the reservoirs depends on numerous physical properties of the reservoirs, such as the permeability of the formations containing the hydrocarbons, the ability of the hydrocarbons to flow through the formations, and/or the proportion of hydrocarbons present, among other things.
Easily produced sources of hydrocarbon are dwindling, leaving less conventional sources to satisfy future energy needs. As the costs of hydrocarbons increase, less conventional sources become more economically attractive to produce. For example, the production of oil sands has become more economical. The hydrocarbons produced from less conventional sources may have relatively high viscosities, for example, ranging from 1000 centipoise (cP) to 20 million cP American Petroleum Institute (API) densities ranging from 8° API, or lower, up to 20° API, or higher. The hydrocarbons harvested from less conventional sources may include bitumen, or other carbonaceous materials, collectively referred to herein as “heavy oil.” The hydrocarbons produced from less conventional sources are difficult to recover using conventional techniques.
Several methods have been developed to recover heavy oil from, for example, oil sands. Strip or surface mining may be performed to access oil sands. Once accessed, the oil sands may be treated with hot water or steam to extract the heavy oil. For formations where heavy oil is not close to the Earth's surface, heat may be added and/or dilution may be used to reduce the viscosity of the heavy oil and recover the heavy oil. Heat may be supplied through a heating agent like steam. The recovered heavy oil may or may not be produced via a production well or wellbore. The production well or wellbore may be the same as the wellbore used to inject the heat for the steam injection. If the heating agent is steam, the steam may condense to water at the steam/cooler-oil-sands (SCO) interface in the formation and supply latent heat of condensation to heat the heavy oil in the oil sands, thereby reducing viscosity of the heavy oil and causing the heavy oil to flow more easily.
A number of steam-based heavy oil processes have been developed for recovering heavy oil. The processes may include, for example, cyclic steam stimulation (CSS), steam flooding, steam-assisted gravity drainage (SAGD), and solvent-assisted steam-assisted gravity drainage (SA-SAGD).
SAGD is a process where two horizontal wells may be completed in the reservoir. The two wells may be first drilled vertically to different depths within the reservoir. Thereafter, using directional drilling technology, the two wells may be extended in the horizontal direction that results in two horizontal wells, each vertically spaced from, but otherwise vertically aligned with, the other. Ideally, the production well may be located above the base of the reservoir but as close as practical to the base of the reservoir, and the injection well may be located vertically 10 to 30 feet (3 to 10 meters) above the horizontal production well. The upper horizontal well may be utilized as an injection well and may be supplied with steam from the surface. The steam may rise from the injection well, permeating through the reservoir to form a vapor chamber (steam chamber). As the vapor chamber grows over time towards the top of the reservoir, the steam may condense at the SCO interface, releasing latent heat of steam and, thereby reducing the viscosity of the heavy oil in the reservoir. The heavy oil and condensed steam may then drain downward through the reservoir under the action of gravity and flow into the lower production well, from where the heavy oil and condensed steam can be pumped to the surface. At the surface of the well, the condensed steam and heavy oil may be separated, and the heavy oil may be diluted with appropriate light hydrocarbons for transportation by pipeline. SAGD processes are described in Canadian Patent No. 1,304,287 and in U.S. Pat. No. 4,344,485.
Before commencing a steam-based heavy oil recovery process, a start-up phase may occur. The start-up phase may condition the reservoir for heavy oil extraction and production by the steam-based heavy oil recovery process. Without a start-up phase, heavy oil may be viscous and immobile. Consequently, it may be difficult for an extraction fluid to penetrate a heavy-oil containing region, containing the heavy oil, to the extent required for a steam-based heavy oil recovery process.
A “water-wet” reservoir is a reservoir that contains water. In water-wet reservoirs, a thin film of water may cover the rock fabric of the reservoir or sand grains. The heavy oil may be located within the pore space and therefore surrounded by the water or the water may be surrounded by the heavy oil. Typically, in reservoirs targeted for heavy oil extraction by a steam-based heavy oil recovery process, the overall pore space will contain 60 to 90% oil and 40 to 10% water, by volume. The presence of the water can interfere with the extraction process until conditioning start-up phase or other conditioning process of the reservoir occurs.
When the steam-based heavy oil recovery process is for example, SAGD, the start-up phase may include preliminary heating the formation by steam. SAGD wellbores may be drilled. Surface facilities and infrastructure required for the injection of steam and production of fluids may be constructed. The time delay between the drilling of the wellbores and the ability to start steam generation can vary from several months (e.g., 6-9 months) to two or more years. After the time delay, the start-up phase may begin, but may then require a period of three (or more) months for completion of the start-up phase. The delay may cause undesirable economics and loss of opportunity. The delay may require the provision of specialized controls, valves, pipes, etc., for the start-up phase. The specialized controls, valves, pipes, etc. may not be needed for SAGD. SAGD, much like any other steam-based heavy oil recovery process, occurs after any start-up phase.
Some start-up phases for SAGD use heat circulation. For example, steam and surfactant may be used to create a foam, as disclosed in U.S. Pat. No. 5,215,146, a heated fluid may be injected, as disclosed in WO 1999/067503 or CA 2,697,417, or the wellbores may be presoaked as disclosed in WO 2012/037147 or US 2011/0174488.
Another start-up phase for SAGD, disclosed in CA 2,766,838, discloses wellbore pair configured to force an initial fluid communication between the production wellbore and the injection wellbore to occur at a selected region along the production wellbore and injection wellbore.
Another start-up phase for SAGD, disclosed in CA 2,740,941, discloses relying on the injection of a start-up fluid at elevated pressures in the injection wellbore. A production wellbore is used to create a pressure sink (voidage) to maximize the available pressure gradient between the production and injection wellbores and as a result help draw the start-up fluid towards the production wellbore. The process is applied only after the production wellbore has been completed with production tubing, artificial lift has been installed or is operational, a way to measure the reproduced start-up fluid is available and a way to store or transport the produced fluids once they are produced to surface is available. The volume of start-up fluid required is substantial, with the representative calculations suggesting required start-up fluid volumes of 500-18,000 meters cubed (m3) to treat a single wellbore pair. A single wellbore pair includes a single production wellbore and a single injection wellbore.
WO 2012/121711 discloses delivering only a small reduction in the time duration of the start-up phase time requirements and no real capital cost reduction benefits as the equipment required to circulate steam in the extraction process of heavy oil must be in place before the start-up phase. WO 2012/121711 discloses fluid circulation followed by a “squeeze step” (described as the shut-off of fluid returns in a wellbore and the inspection of an increase in fluid production at another wellbore). WO 2012/121711 discloses that oil production can only occur after the successful completion of three steps, namely solvent circulation, steam circulation and steam squeeze.
WO 2013/071434 discloses that in order to accelerate the start-up phase of a SAGD wellbore pair, it is preferable to establish a physical connection between the injection and production wellbores. The physical connection can be established by: (1) drilling the injection and production wellbores such that the toes of wellbores intercept; (2) drilling a vertical wellbore that intercepts the toe locations of the injection and production wellbores (creating the physical connection via it's wellbore); or (3) propagating a fracture between the toe locations of the injection and production wellbores. Thus, WO 2013/071434 discloses that, by creating a physical connection (or a high permeability path by fracturing), it is possible to create a continuous unidirectional pathway between the injection and production wellbores for the heated fluids used to start-up the wellbores. At the end of the start-up phase, it may then be necessary to plug the intersection point connecting the injection and production wellbores. Hence, the start-up phase disclosed in WO 2013/071434 is complex and expensive to implement. The start-up phase disclosed in WO 2013/071434 is unlikely to maintain the required mechanical integrity for the entire duration of the start-up phase.
CA 2,698,898 discloses a method of initiating or accelerating fluid communication between horizontal wellbores located in a formation of very limited fluid mobility at start-up. A selected amount of a solvent such as xylene, benzene, toluene or phenol, is injected at sub-fracturing conditions and ambient temperature into a first of the wellbores. The method may be employed for a start-up phase for the recovery of heavy oil using, for example, steam assist gravity drainage.
The present disclosure provides methods for reducing the duration of the start-up phase for steam-based heavy oil recovery processes so that these processes can more quickly recover heavy oil. It is economically advantageous to reduce the start-up phase time for steam-based heavy oil processes.